Advances in Gas Turbine Technology Part 6 ppt

For that purpose the researches conducted at Suplacu de Barcau 2xST 18 Cogenerative Power Plant has focused on the afterburning installation as integral part of the cogenerative group in

influence mainly the superheater of the heat recovery steam generator (with effects on temperature, flow rate etc.) The design of the gas turbine – afterburning installation – heat recovery steam generator system must take into account these variables for insuring the steam parameters required by the technological process The active control of the combustion is a concept already accepted and the new generation of afterburning installations will need to answer to the requirements of the new “smart” aggregates which automatically take into account the emissions, the energetic efficiency and the process requirements (PIER, 2002) For that purpose the researches conducted at Suplacu de Barcau 2xST 18 Cogenerative Power Plant has focused on the afterburning installation as integral part of the cogenerative group in terms of stack emissions, superficial temperature profile and power quality (Barbu et al., 2010)

as well as on its interaction with the heat recovery steam generator

2 General principles of the mathematical modelling of the

thermo-gas-dynamic and chemical processes in the combustion chambers

The classical approach of the combustion chambers study assumes as a general rule the embracing of a steady character of the phenomena taking place in these installations, constituting only a quasi-adequate manner to the problem of analysing the unsteady phenomena generating important collateral effects The physical-chemical phenomena succeeding in the combustion chamber are extremely complex, each of them (injection, atomization, vaporization, diffusion, combustion) rigorously depending on the physical factors such as air excess, gases pressure, temperature and velocity in the chamber It may

be admitted that the combustion is normal as long as the fluctuations detected in the combustion chamber only depend on the local conditions and they are randomly distributed

in the chamber The high level of complexity of the phenomena, associated to the flow instabilities, the heat transfer and the combustion reactions, makes them inaccurate to model using simplified mathematical models which only globally consider the processes and which are only slightly dependent on the combustion chamber geometry, the combustion configuration, the walls‘ screening or the intermediary reactions in the flame Therefore, here is studied the complex and coupled problem of mathematical modelling for pulsating flow (numerical integration of Navier-Stokes equations with a closing model application), the influence on heat transfer (considering the radiation and convection), the combustion reactions (applying complex combustion mechanisms with high number of reactions and intermediary chemical compounds) The generalized model accurately tracking the complex processes in the combustion chamber may be developed as a group of modules, each associated to a phenomenon (flow, heat transfer, combustion reactions and dispersion phase evolution) This modular approach method allows the separate development of several sub-models with higher accuracy for a certain class of problems Hence the problem of „closing“ the equations system describing the studied phenomenon may and has been solved by using several turbulence models: k-ε (standard, realisable or RNG), Reynolds-stress model, LES - large eddy simulation (high scale modelling), or lately, due to the increase in calculation efforts, DNS – direct numerical simulation

2.1 Mathematical models used for simulating flow, heat transfer and combustion in combustion chambers

There are two fundamentally different manners used for describing the fluid flow equations: the Lagrangian and Eulerian formulations From the Lagrangian formulation perspective

Eulerian formulation of the biphasic flow does not allow the direct application of the solving schemes existing in the case of monophasic flow As a consequence of this averaging problem in most numerical models the Lagrangian formulation is used for describing the dispersion phase The relation between the Lagrangian and the Eulerian formulations is given by the Reynolds transport theorem Therefore the components on the three axes may

be combined in a single vectorial equation:

as well as equations defining their variations are needed In flows with turbulent character additional transport equations need to be solved Mass conservation equation, or continuity equation, may be written:

( i) m i

Equation (2) is the generalized formulation of mass conservation equation and is applicable

for incompressible or compressible flows The source term S m represents the mass added to the continuous phase, mass resulted from the dispersion phase (due to liquid droplets‘ vaporization) or a different source For axi-symmetric bi-dimensional flows, the continuity equation in given by:

where p is the static pressure, τ ij is the tension tensor and ρg i and F i are the internal and external gravitational forces (e.g occurring from the interaction with the dispersion phase)

on direction i F i also includes other source terms depending on the model (such as for

porous environment case) The tension tensor τ ij is given by:

23

where µ is the dynamic viscosity and the second term in the right side of the relation

represents the effect of volume dilatation For axi-symmetric bi-dimensional geometries the axial and radial impulse conservation equations are given by:

where k ef is the effective conductivity (k ef = k + k t , where k t is turbulent thermal conductivity,

defined relative to the utilized turbulence model) and J j‘ is the diffusive flow of the chemical compound j‘ The first three members in the left side of equation (8) represent the energy

transfer due to conduction, chemical compounds diffusion and respectively viscous

dissipation The term S h includes the heat exchanged in the chemical reactions or other volume heat sources In equation (8),

is the corresponding enthalpy of the compound, and the reference temperature is T ref = 298.15 K In combustion studies, when the PDF based nonadiabatic model is used, the model

requires solving an equation for total enthalpy, set by the energy equation:

In the hypothesis of a unitary Lewis number (Le = 1), the conduction and diffusion terms of

the chemical compounds are combined in the first term in the left side of equation (13), while the viscous dissipation contribution in the nonconservative formulation occurs as the second term of the equation Total enthalpy H is defined by:

j j j

T Equation (8) includes the terms of pressure and kinetic energy work, terms neglected in

incompressible flows The decoupled solving method for the flow equations does not require including these terms in incompressible flows However these terms must always be considered when using coupled solving method or for compressible flows Equations (8) and (13) include the viscous dissipation terms representing the thermal energy created by the viscous tension in the flow When using the decoupled solving method, the energy equation formulation does not need to explicitly include these terms because the viscous heating is in most cases neglected The viscous heating becomes important when the

Brinkman number, B r, is close or higher than the unitary value, where

and ΔT represents the temperature difference in the system The compressible flows usually

have a Brinkman number B r ≥ 1 In the same time equations (8) and (13) include the

enthalpy transport effect due to chemical compounds diffusion For the decupling solving method the term j j

j i

model (PDF) this term does not explicitly appear in the energy equation, being included in the first term in the right side of equation (13) The energy sources S h include in equation (8) the energy due to chemical reactions

0

,

Tref j

3 Suplacu de Barcau 2xST 18 cogenerative power plant

Suplacu de Barcau 2xST 18 Cogenerative Plant (fig 1), with beneficiary SC OMV PETROM

SA, is located in Bihor County, Romania, 75 km from Oradea Municipality The main technical data are given in table 1 The plant was integrally commissioned in 2004 working

in the framework of Suplacu de Barcau Oil Field The electrical energy is used for driving the reducing gear boxes from the oil wells, the compressors, the pumps, for lighting etc and the thermal energy (steam) is injected in the deposit being necessary in the oil extraction technological process and/or for other field requirements (heating the buildings or technological pipes) Suplacu de Barcau 2xST 18 Cogenerative Plant comprises two groups (fig 1, right) which may work together or separately Each group includes a ST 18 gas turbine (fig 2, left), an afterburning installation (fig 2, centre), a heat recovery steam generator (fig 2, right) and additional installations The heat recovery steam generator of each cogenerative group is a fire tube type boiler with two flue gas lines – one horizontal and the other vertical, comprising: the uncooled afterburning chamber; the superheater insuring the 300 °C steam temperature; the pressure body producing the saturated steam; the feed water heater assembly – water pre-heater insuring the necessary parameters of the water supplying the pressure body The superheater is a coil type heat exchanger with 12 coil pipes (ø 38) welded in the steam inlet down-tanks (upper tank – fig 3, centre) of the pressure body and superheated steam outlet (lower tank – fig 2, right) The steam in the pressure body enters the upper tank through a PN40 DN150 connector (placed in the middle

of the tank) and is distributed to the 12 coil pipes, then enters the lower tank and is delivered to the users

The gases from the afterburning chamber follow the horizontal line of the heat recovery steam generator (superheater – pressure body) then the vertical one (feed water heater – water pre-heater – stack) Each cogenerative group is able to work in any of the three versions given in table 1, but the basic one is version I 2xST 18 Cogenerative Power Plant is working automatically, the exploitation personnel being alerted by the command panel, through optical signalling and alarm horns, regarding the deviations of the supervised parameters or the damages occurrence Certain parameters (pressures, temperatures, flow rates etc) of the equipments are archived and displayed with the help of an acquisition system

Fig 1 2xST 18 Cogenerative Power Plant view (left) and gear placement (right)

1 Cogenerative group

version afterburning + heat Gas turbine +

recovery steam generator

Gas turbine + heat recovery steam generator

Heat recovery steam generator + afterburning

3 Gas turbine type ST 18 (Pratt & Whitney - Canada)

4 Boiler type Fire tube boiler (SC UTON SA Onesti - Romania)

5 Electric generator type GSI-F (Electroputere Craiova - Romania)

6 Electrical power delivered

Fig 2 ST 18 gas turbine (left), afterburning installation burner (centre) and heat recovery steam generator (right) at 2xST 18 Cogenerative Power Plant

Fig 3 Superheater of the heat recovery steam generator at 2xST 18 Cogenerative Power

Plant

3.1 The afterburning installation at Suplacu de Barcau 2xST 18 cogenerative power

plant

The afterburning installation (burner with automatics) at 2xST 18 Cogenerative Power Plant

was delivered by Saacke (www.saacke.com – Germany) and has the specifications given in

table 2 The burner (fig 4), produced by Eclipse – Holland, is the “FlueFire” type dedicated

to this kind of application It may be placed directly in the flue gases flow, between the

turbine and the recovery boiler, but may work as well on fresh air The burner has 21 basic

modules located on 3 natural gas fuelling ramps and 2 flame propagation modules The flue

gases from the gas turbine are introduced in the “FlueFire” burner through an adaptation

section The mixture with the fuel is obtained through the swirling motion of the flue gases

exhausted from the turbine in the fuel jets This leads to the cooling and the stabilization of

the combustion in the burner front allowing downstream high temperatures at a low NOx

content The air, delivered by a fan (fig 4, right), is introduced in the adaptation section

through a distribution system built to insure an uniform distribution in the transversal

section because the emissions depend on the unevenness of the flow, velocity, oxygen

concentration etc The afterburner modules are built in refractory steel, laser cut, for

insuring the necessary uniformity

Each module is fitted in the natural gas fuelling ramps using two gas nozzles in order to

allow the free dilatation of the assembly The ignition is initiated with the help of a pilot

burner placed in the lower area of the afterburning burner and the supervision of the flame

is insured by a UV type “DURAG D-LX 100 UL” detector placed in the upper area

With air at 20 0C (version III) 6 MW

4 Flue gases temperature at the inlet of the burner 524 0C

5 Flue gases temperature at the end of the afterburning chamber (versions I and III) 770 0C

Table 2 Technical specifications regarding the afterburning installation at 2xST 18

Cogenerative Power Plant

Fig 4 The burner in the afterburning installation at 2xST 18 Cogenerative Power Plant (left, centre) and the fresh air fan (right)

4 Gas turbine – afterburning interaction

The flue gases flow in the outlet section of the gas turbine is generally turbulent and unevenly distributed In some areas at the inlet of the afterburning installation backflows may occur A uniform flow distribution is an important factor concurring to the good working of the afterburning and to the performances of the heat recovery steam generator Grid type burners are designed to distribute the heat uniformly in the transversal section of the heat recovery steam generator, fact requiring careful oxygen feeding in order to avoid high NOx emissions and variable length flame The flow rate, the temperature, the composition of the flue gases exhausted from the gas turbine depend on the fuel type, load, fluid injection in the gas turbine (water, steam), environmental conditions etc The gas turbines used in industrial applications are fuelled by liquid or gaseous fuels Regarding the liquid fuels, for economical reasons, there are usually used cheap fuels such as heavy fuels, oil fuels or residual products from different manufacturing processes or chemisation (Carlanescu et al., 1997) Using these types of fuels raises problems concerning: insuring combustion without coating, decreasing the corrosive action caused by the presence of aggressive compounds (sulphur, traces of calcium, lead, potassium, sodium, vanadium) and problems concerning pumping and spraying (heating, filtration etc.) When considering using aviation gas turbines for industrial purposes (existing aviation gas turbines with minimal modifications) the possibilities of using liquid fuels are limited For each case the technical request of the beneficiary must be analyzed in conjunction with the study of fuel characteristics affecting the processes in the combustion chamber (density, molecular mass, damping limits, burning point, volatility, viscosity, superficial tension, latent heat of vaporization, thermal conductibility, soot creation tendency etc.) For the gaseous fuels the problem is easier considering the high thermal stability, the absence of soot and ashes, and the high caloric power In this case the problems concern mostly the combustion process in conjunction with the requirements of the used gas turbine For the valorisation of the landfill gas the TV2 – 117A gas turbine was modified to work on landfill gas instead of kerosene by redesigning the combustion chamber (Petcu, 2010) Numerical simulations and experimentations have been conducted for the gas turbine working on liquid fuel (kerosene) and gasesous fuels (natural gas, landfill gas) The boundary conditions have been either calculated or delivered by the gas turbine manufacturer for three working regimes: take-off, nominal and idle The results are presented in table 3 with the corresponding temperatures for each regime The temperature fields are displayed in rainbow with red representing the

highest value The most important result refers to the fact that the numerically obtained temperatures are close enough to the ones indicated by the manufacturer, the differences being explained by the simplifying hypotheses introduced in the simulations Analyzing the numerical results it may be observed that the flame shortens (column 5) with the decrease in regime, but it fills better the area between two adjacent injectors (column 6) The main criterion validating the numerical results has been the averaged turbine inlet temperature (Tm) in the conditions of fuel and air flow rate imposed by the working regimes of the TV2 – 117A gas turbine For working on gaseous fuel, the TV2 – 117A gas turbine has suffered adjustments on the fuel system level and particularly on the injection nozzles The starting point in designing the new injection nozzle was a previous application on the TA2 gas turbine resulted by modifying the TV2 – 117A Table 4 presents the variation of the CH4

mass fraction indicating the injected jet shape (left) and the burned gases temperature in the combustion chamber outlet/turbine inlet section (right) for different working regimes The geometrical parameters of the injection nozzle were set based on the numerical temperature fields in the turbine inlet section and aiming to obtain a compact fuel jet which avoids the combustion chamber walls It must be noted that a stable combustion process has been obtained using a gaseous fuel in a combustion chamber designed for a different type of fuel (kerosene) The numerical simulations made possible narrowing the variation domains for the geometrical and gas-dynamic parameters in order to establish the constructive solution

of the combustion chamber for working on landfill gas The numerical results have been used for designing and manufacturing the new injection nozzle for the eight injectors of the TV2 – 117A gas turbine, transforming it into the TA2 aero-derivative From tables 3 and 4 it may be noticed that by changing the fuel and the working regime the temperature distribution in the section of interest is modified, fact that might affect the afterburning installation performances For reducing the NOx emissions, reducing the temperature in the combustion area is applied through water or steam injection

axial-Thermal field

on the frontier between two sections

by the air passing over the downstream edges of the turbulence nozzle The efficiency of the water or steam injection in reducing the NOx emissions has been highlighted by many authors and may be expressed by the following relation (Carlanescu et al., 1998):

Fig 5 Temperature field in the axial-median section of the TA2 combustion chamber, Tm

=1063 K, without water injection (left) and with water injection (right) (Popescu et al., 2009)

Relation (18) may be applied for liquid as well as for gaseous fuels, showing that approximately 80 % reduction in the NOx emissions may be obtained at equal water/steam-to-fuel flow rates (x = 1) The water injection is more efficient at higher combustion

pressures and temperatures where the NOx production is higher and less efficient at lower pressures and temperatures For the independent running of the TA2 gas turbine on methane, without afterburning, the numerical simulations (fig 5 – 6) regarding the water injection have shown a NOx reduction of over 50 % (Popescu et al., 2009)

Fig 6 Temperature field in the combustion chamber outlet section, Tm =1063 K, without water injection (left) and with water injection (right) (Popescu et al., 2009)

However, theoretical and experimental researches on a turbojet have shown that the steam injection reduces the NO emissions up to 16% (mass fractions) when a steam flow which doubles the fuel flow is introduced (Benini et al., 2009) At the same ratio, the NO reduction

in the water injection case is approximately 8% The steam injection slightly reduces the CO level while the water injection raises it with the increase in the injected water quantity Using the NASA CEA program (McBride & Gordon, 1992; Zehe et al., 2002), the combustion have been analyzed in the TA2 gas turbine for methane, natural gas (the composition at Suplacu de Barcau Cogenerative Plant) and landfill gas (equal volume proportions of methane and carbon dioxide) in the pressure and temperature conditions recommended for different working regimes of the gas turbine (Tm = 1063, 1023 and 873 K) The air excess coefficients have been established for each fuel in the dry working cases in order to obtain the same temperature of the reaction products for a corresponding fuel quantity Starting from these initial data and increasing the injected water quantity up to 50 % of the fuel quantity, a decrease in temperature has been noticed for each 10 % injected water of approximately 1.46 degrees for methane, 1.62 degrees for natural gas and 1.36 degrees for landfill gas It was then aimed to establish the dependence of the quantitative water-to-fuel ratio at supplementary fuel injection in order to maintain the maximum temperature in the gas turbine These analysis have been made only for methane for the same stable working regimes of the TA2 gas turbine (Tm = 1063, 1023 and 873 K) In the theoretical calculations for methane some limitations have been next applied: a ratio between the fuel quantity in the water injection case and the initial fuel quantity of maximum 2; a minimum oxygen concentration in the flue gases from the gas turbine of 11 % volume for afterburning running The general reaction for methane combustion when water injection is involved is given by equation (19) and the algorythm used in the NASA CEA program for determining the water injection influence is presented in fig 7:

Fig 7 The algorithm used in NASA CEA program to determine the water injection

influence (subscript „x“ denominates the seeked coefficients for the desired fixed

temperature)

The thermodynamic properties of the system have been tracked with focus on the reaction products concentrations and particularly CO and NOx In these conditions the calculations have been made for a water coefficient (denoted a) of maximum 8 (fig 8) For a higher value than 6.5 an instability of the curves occurs For a value of the coefficient of approximately 2.8, the gas turbine at the regime Tm = 1063 K is close to the minimum oxygen limit of 11% needed for the afterburning In fig 9 and 10 the water coefficient a is limited to 4 Therefore

we may have a maximum water coefficient of 2.8 for the regime Tm = 1063 K, 3.1 for the regime Tm = 1023 K and 3.5 for the regime Tm = 873 K, having as result the inaccessible areas

of emissions reduction for the TA2 gas turbine with water injection when using the afterburning The theoretical calculations indicate that the NOx emissions for the TA2 working at the regime Tm = 1063 K with afterburning may not be lower than 40 ppm The unevenness of the flow when exiting the combustion chamber (tables 3 and 4, fig 5 and 6) and the variation in the burned gases composition (fig 8 – 10) affect the afterburning process and confirm the necessity of a fine control on the injected water quantity particularly when a significant reduction of the emissions is aimed Therefore the afterburning is affected from the efficiency, emissions, flame stability points of view as well

as from the corrosion on the elements subjected to the burned gases action

The combined actions of water vapours and oxygen concentration and high temperature of the flue gases represent the recipe for an accentuated corrosion (Conroy, 2003)

Fig 8 Fuel coefficient (b) variation depending on injected water coefficient (a)

Fig 9 NOx concentration variation depending on injected water coefficient (a)

Fig 10 O2 concentration variation depending on injected water coefficient (a)

generator As „end of the line“ element it is its duty to maintain the temperature of the superheated steam, imposing mechanical systems and automatics with well defined functions and roles taken into consideration by the designer Increasing the nominal parameters of modern heat recovery steam generator as a result of the increased performances in gas turbines led to a superheater area larger than that of the vaporizing system, the superheater becoming a large metal consumer as well as the heat exchanger with the highest thermal demand As consequence, the superheater needs the proper consideration in the design process as well as in activity If the flow process in the superheater pipes is admitted as isobar, the increase in temperature takes place according

to an exponential law The value of the coefficient of thermal unevenness in the flue gases flow entering the superheater stage depends on the constructive shape and the thermal diagram This coefficient is defined by (Neaga, 2005):

max med

273273

g t g

t k t

 

where the index shows that the temperatures are indicated for the inlet of the stage, t gmax

and t gm ed being the maximum and respectively the averaged temperatures of the gases at the inlet The ability of the steam to absorb the heat of the flue gases in different areas of the volume occupied by the stage leads to unevenness affecting the safe running of the heat exchanger The researches show that the highest unevenness on the outlet of the stage is registered in the counter-stream flow of the thermal agents regardless of the number of stages of the superheater and the lowest in the uniflow (Neaga, 2005) The characteristics of the superheated steam are different for the radiation and convection superheaters The radiation superheater absorbs more heat at low loads while the convection one absorbs more heat at higher loads (Ganapathy, 2001) The superheaters usually have more stages, the radiation and convection combined ensuring a uniform temperature in the steam for a larger range of loads When the superheater consists in only one stage the problem of controlling the temperature in the superheated steam becomes more complicated The steam temperature can usually be maintained constant in the 60 – 100 % load range but several factors act on the superheated steam temperature: heat recovery steam generator load, air excess coefficient at the furnace outlet, initial dampness of the fuel, calorific value of the fuel etc As consequence, the temperature control systems must comply with certain conditions: low inertia, large control range (regardless of the variable parameter leading to variations in the superheated steam temperature), safe running construction, minimal manufacturing and running expenses etc